The present invention relates to methods for downhole fluid analysis and real time production control of a well. More particularly, the invention relates to an improved method for analyzing thermodynamic phases of complex fluids downhole, and for using such analyses for real time process control.
The control of fluid produced from each hydrocarbon reservoir zone can significantly improve the recovery factor. It can also minimize the production of undesirable fluids such as water and gas. In addition, such control could assist reservoir engineers with flood injections and chemical agent treatment.
Phase transitions play an important role in the producibility of oil or gas wells and their associated reservoirs. Fluid produced from an oil well will typically have a number of hydrocarbon components and, while these may coexist as liquid at the temperature and pressure of the reservoir rock, the lighter components may begin to evolve as gas as the wellbore and formation pressure is reduced. Such evolution of gas in the reservoir rock can seriously decrease the oil phase relative permeability and, ultimately, the fraction of oil that may be recovered. Knowledge of the bubble point is also useful in determining the composition of the hydrocarbon mixture in the reservoir. Similarly, in gas wells, heavier components may begin to condense as a liquid as gas is produced. Liquid in the pore spaces of a gas well will similarly reduce the permeability to gas. It is important to maintain either pure liquid or pure gaseous phase in the reservoir, depending on the type of well.
Reservoir performance calculations greatly benefit from a knowledge of the location of the fluid (p, T, x) pressure-temperature-composition phase transitions. At either reservoir or producing zone conditions the most significant phase borders are the formation of a liquid from a gas (dew point) and a gas from a liquid (bubble point). The phase behavior of black oils is usually dominated by the mole fraction of low molecular mass components, while for retrograde condensates the phase behavior is determined by mole fraction of high molecular mass components.
Fluid phase behavior also plays an important role in production engineering both down hole and at surface. It is often desirable to produce with the xe2x80x9cdrawdownxe2x80x9d, or decrease in wellbore pressure relative to the formation pressure, as large as possible to give the greatest production rate. Drawdown is limited, however, by the need to avoid phase changes in the fluid. In addition, failure to maintain a single phase in a horizontal well can create gas pockets that inhibit flow in production tubing. Both Reservoir and Production Engineers require the hydrocarbon phase be maintained homogeneous to optimize production while minimizing risk of reservoir damage.
Conventionally, there are several methods by which the phase behavior of reservoir fluids can be determined. However, none of these methods lend itself to real-time down-hole sensors for in situ production control. Empirical correlations on laboratory data have been used to estimate phase borders. Alternatively, a bubble point can be estimated from a compositional analysis of fluid samples with an equation of state. Typically, samples collected down-hole and brought to the surface are liable to undergo both reversible and irreversible changes such as wax and asphaltene separation, that arise from temperature and pressure changes. In addition, the imperfect fluid transfer between sample apparatus and measuring apparatus alters the composition. Fluid thermophysical property analyses can be obtained at the well head, so reducing the time between sample collection and analysis. However, these approaches all require the handling and perhaps transportation of hazardous fluids. Finally, some properties of well fluids have been determined with a commercially available wireline tool down-hole, without removing the sample from the well. Commercial tools that can be used for this purpose are the Schlumberger Modular Formation Dynamics Trester (MDT) and the We ster n-Atlas Reservoir Characterization Instrument (RCI). Although in theory such devices could be used to provide, for a limited time period, real time in situ fluid properties, the sensors and methods are not sufficiently reliable for permanent or even semi-permanent operation.
None of the methods described above are performed on a routine basis and certainly never sufficiently often or rapidly to provide real-time data for process control. The only viable solution is permanent or semi-permanent down-hole monitoring.
Thus, it is an object of the invention to provide a method of accurately and efficiently determining thermophysical properties of both reservoir and produced fluid.
In particular, it is an object of the invention to provide a method of determining the phase border in a way that allows for improved real time process control and reservoir optimization with downhole chokes.
It is a further object of the invention to provide an improved method and system of controlling pressure in a well using real-time measurements of phase characteristics of fluid in the well.
It is a further object of the invention to provide measurements that minimize sample manipulation and transportation, thus ensure sample integrity.
It is a further object of this invention to provide a method and apparatus for accurately determining phase characteristics in a flow-by tool that does not require that a sample be captured in a closed volume.
It is a further object of this invention to provide a method and apparatus for determining phase characteristics in the well that does not require physical manipulation of the pressure of the fluid with moveable pistons, plungers or the like.
It is a further object of the invention to provide information on the phase transition pressure so that the flow control valves may be operated without incurring a phase transition in the reservoir or borehole.
As used herein, the term xe2x80x9creal timexe2x80x9d with respect to determining phase characteristics is defined as a frequency which allows accurate process control. In general, the higher the frequency of measurement the more accurate the control, since the phase boundary varies over time with variations in the fluid composition. However, in many situations monitoring the phase characteristics once per week will be more than sufficient to avoid the negative effects of producing too close to the phase boundary.
As used herein, the term xe2x80x9cacousticxe2x80x9d is defined as including both the sonic and ultrasonic frequency ranges.
The preferred method of phase boundary detection involves using an acoustic transducer to create cavitation. In general, cavitation is considered impractical for fluid pressures above about 1 MPa and would appear impossible down hole. However, such generalities appear to have been formulated on the basis of measurements in water at pressures at least 1 MPa above phase separation with low-power cavitation sources. For a fluid close to the phase separation pressure, it has been found that localized pressure reductions created in acoustic waves will give rise to the evolution of transient cavitation bubbles at static pressures higher than the thermodynamic bubble point pressure.
The bubbles thus formed can be detected at the site where they are produced by monitoring the acoustic properties of the liquid. This is preferably done by monitoring the acoustic impedance of the acoustic transducers used to cavitate the fluid. At the first appearance of a bubble, even a transient bubble, the acoustic impedance mismatch between transducer and fluid is greatly altered. This in turn produces a change in the electrical impedance of the transducer.
Advantageously, according to the invention, a combination of measured static pressure and the detection of cavitation with an acoustic source generating a known acoustic pressure provides a determination of the bubble pressure. For permanent monitoring applications, this approach can be applied to both heterogeneous stratified and homogeneous mixed flow regimes when a sample is captured as a continuous hydrocarbon phase, and the volume of the secondary phase is determined by other means. Furthermore, the strategy can be used on flowing fluid, without recourse to sampling, within the completion tubing independent of production stream deviation in horizontal stratified flow provided the sensors are located in the hydrocarbon-continuous phase.
According to the invention, the acoustic pressure generated by the acoustic source can be determined from either calibration or a theoretical model based on finite element analysis and known physical properties of the transducers"" environment. The semi-empirical model uses both the density and sound speed of the fluid. These properties can be determined with either the same or an independent transducer.
According to the invention, cavitation and the formation of bubbles can be determined by one or more of the following methods: passive emissions, transmission, reflection, sound speed, sound attenuation, optical, Doppler, back-scattering, holography, microscopy, or Mie scattering. However the preferred method is by measuring the variance in impedance of an acoustic transducer.
According to one embodiment of the invention, a system and method of fluid analysis in a hydrocarbon borehole is provided for determining phase characteristics of a formation fluid. Acoustic energy is emitted into the fluid downhole at a level which causes a phase transition in the fluid. The pressure associated with the phase transition is then determined from the level of emitted acoustic energy. Advantageously, the determination of the phase transition pressure need not rely on mechanical means to substantially alter the volume of a sample of the fluid.
The acoustic energy is emitted by an acoustic transducer that can be installed either semi-permanently or permanently downhole in the well. The acoustic transducer can be contained in a flow-by tool that does not require that a sample be captured in a closed volume. Either the bubble point or the dew point can be detected. In the case of bubble point detection, the bubbles in the fluid can be detected by sensing variations in impedance of the acoustic transducer, and the level of emitted acoustic energy can determined by measuring the electrical energy used to drive the transducer.
According to another embodiment of the invention, a control system is provided for a hydrocarbon well. A control valve system is used to control the flow and the pressure of fluid being produced. A real time sensor is provided downhole and is used to make real time measurements of phase characteristics of the fluid. A controller is used to control the valve system so as to reduce the risk of undesirable phase transitions in the fluid based on the real time measurements made by the sensor.
The real time sensor can be installed permanently or semi permanently downhole in the well. The sensor preferably includes an acoustic transducer configured to emit acoustic energy into the fluid at a level which causes a phase transition in the fluid. The controller preferably determines the level of acoustic energy emitted into the fluid, and also determines the pressure associated with a phase transition using the level of emitted acoustic energy. Advantageously, the determination of the pressure associated with the phase transition need not rely on mechanical means to substantially alter the volume of a sample of the fluid. The phase transition detected can be the bubble point or the dew point. The phase transition pressure is preferably determined by sensing variations in impedance of the acoustic transducer which indicate the presence of bubbles in the fluid.
According to another embodiment of the invention, a system for determining phase characteristics of a hydrocarbon fluid sample in a bottle is provided. An acoustic transducer emits acoustic energy into the fluid at a level which causes a phase transition in the fluid. A controller is provided to determine the level of acoustic energy emitted into the fluid, and determine the pressure associated with the phase transition using the level of emitted acoustic energy. The system can be used to detect the bubble point or the dew point. The pressure associated with the phase transition is preferably determined by sensing variations in impedance of the acoustic transducer. The bottle preferably includes a hydraulically actuated piston to control the pressure of the fluid sample.